Method for Increasing the Fluid Productivity of a Hydraulically Fractured Well

ABSTRACT

A method for increasing the fluid productivity of a hydraulically fractured well and reducing the production of particulate proppant plugging during production of fluids from a hydraulic fracture in a subterranean formation penetrated from an earth surface by a well by the use of smart memory particles and dissolvable proppant particles in the fracturing fluid.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority, under 35 U.S.C. §119(e), of U.S. Provisional Application No. 61/066,272, filed Feb. 19, 2008, incorporated herein by this reference.

FIELD OF THE INVENTION

The present invention relates to a method for increasing the fluid productivity of a hydraulically fractured well and reducing the production of particulate proppant during production of fluids from a hydraulic fracture in a subterranean formation penetrated from an earth surface by a well.

BACKGROUND OF THE INVENTION

In the production of fluids from subterranean formations, it is found that fracturing the formation in many instances leads to increased productivity from wells penetrating the formation. Fracturing is used to form fractures in formations penetrated by a cased well where perforations are positioned in a zone of interest and thereafter a fracturing fluid is injected at sufficient pressure to cause fractures in the formation which provide paths for fluid flow through the factures. Similarly formations may also be fractured from uncased wells. To facilitate holding the fractures open, solid particle proppants are frequently injected with the fracturing fluid (proppant slurry) or subsequent to the injection of the fracturing fluid to position small particulate particles in the fractures so that the fractures remain open and the permeability of the fractures as a result of the small particles positioned in the fractures permits greater flow through the fracture to the wellbore.

In many instances it is found that fines from the formation, proppants and the like may be produced back (flow back) into the wellbore during initial production. Frequently these problems may continue after an initial period. To eliminate this flow back of material, various techniques, such as gravel packing, have been used. Gravel packing involves positioning a screen of gravel around the inside of the wellbore to collect and prevent the flow of particulates into the wellbore. If particulates are allowed to flow into the wellbore they can fill the wellbore to the level of the fractures resulting in production reduction or loss. These materials in the produced fluids if produced to the surface may result in shortening the life of production equipment and the like.

A wide variety of particulate materials have been used as proppants. These materials can comprise any particles deemed to have sufficient strength to “prop” the fractures open to permit greater flow.

In some instances, such as shown in U.S. Pat. No. 7,086,460 (the '460 Patent) issued Aug. 8, 2006 to Phillip D. Nguyen and Johnny A. Barton and assigned on its face to Halliburton Energy Services, Inc., the use of torsion spring particulates which may include shape memory alloys and shape memory polymers is disclosed. These particulates comprise a number of torsion springs prepared from metal wire which are compressed and inserted into the center of a mass of fibrous material, such as stainless steel wool or fibrous sponge and placed inside a mold. An aqueous soluble mixture of filler and adhesive is then injected into the mold cavity to encapsulate the compressed springs. After curing, the contents inside the mold are transformed into a solid ball which can be spherical or elliptical in shape. These balls are decomposed in the formation to the extent of releasing the spring wire into contact with the inside of the formation. These balls may be injected with other proppants and after the restraining materials are removed, the springs tend to be released into contact with the inside of the fracture and restrict movement of proppant back out of the fracture during the production of fluids from the well. The soluble fillers are disclosed to be water soluble. This reference is hereby incorporated in its entirety by reference.

In U.S. Pat. No. 6,752,208 B1 (the '208 Patent) issued Jun. 22, 2004 to Phillip D. Nguyen and assigned on its face to Halliburton Energy Services, Inc., it is disclosed that compressed sieves made from a shape memory material are introduced into a hydraulic fracture. These compressed sieves are made from a shape memory material comprising a nickel and titanium alloy which may be compressed into different shapes but which returns to its original shape with considerable force after reaching a given temperature. The devices shown in this reference are of a variety of shapes resembling screens and are disclosed to be effective to filter and retain proppants which may be injected with the screens into subterranean formations. The alloy materials are disclosed to remain wedged in the fractures after they return to their original shapes where they filter and retain proppants which may otherwise be produced as proppant flowback. This reference is hereby incorporated in its entirety by reference.

U.S. Pat. No. 7,192,496 B2 (the '496 Patent) issued Mar. 20, 2007 to Craig Wojeik and assigned on its face to ATI Properties, Inc. discloses methods for producing nickel-titanium shape memory alloys. The reference discloses that the alloys can be designed to return to their original shape at various temperatures. This reference is hereby incorporated in its entirety by reference.

The positioning of the smart memory alloy proppants in the fractures as disclosed above may result in retaining proppants and other particulates in the fracture but in so doing may also result in reducing the flow rates through the fracture or blocking the fracture by the accumulation of proppant and fine formation particles at the sieves.

Accordingly, a continuing effort has been directed to the development of methods whereby smart memory alloy materials may be used in a subterranean formation without the disadvantages of the reduction in flow through the fracture or blocking the fracture.

SUMMARY OF THE INVENTION

The present invention comprises a method for reducing the production of particulate proppants and fracture plugging during production of fluids from a hydraulic fracture in a subterranean formation penetrated from an earth surface by a well and increasing the fluid productivity of the well, the method comprising: injecting a fluid comprising material such as shape memory alloy (SMA) proppants and super elastic proppants having an expansion temperature below a temperature of the subterranean formation and dissolvable proppant particulates into the fracture through the well; maintaining the SMA proppant in the fracture for a time sufficient for the SMA proppants to reach at least the expansion temperature; and, producing fluids from the fracture through the well and dissolving at least a major portion of the dissolvable proppant particulates.

In embodiments, the invention is directed to a method of increasing productivity while reducing the production of particulate proppants during production of fluids from a hydraulic fracture in a subterranean formation penetrated from an earth surface by a well. The method comprises:

-   -   a) injecting a fluid comprising smart memory alloy proppants         having an expansion temperature below a temperature of the         subterranean formation and dissolvable proppant particulates         into the fracture through the well;     -   b) maintaining the smart memory alloy proppants in the fracture         for a time sufficient for the smart memory alloy proppants to         reach at least the expansion temperature; and,     -   c) producing fluids from the fracture through the well and         dissolving at least a major portion of the dissolvable proppant         particulates.

DESCRIPTION OF PREFERRED EMBODIMENTS

According to the present invention, a method is disclosed for reducing the production of particulate proppant and fracture plugging during the production of fluids from a hydraulic fracture in a subterranean formation penetrated from an earth surface by a well bore is disclosed.

The method includes injecting a fluid containing SMA proppants having an expansion temperature below a temperature of the subterranean formation but above the temperature at which the fluid (proppant slurry) containing the proppants is handled and injected. The SMA proppant particles may be of any desired shape, such as spheres, cubes, pyramids, oblate or prolate spheres, cylinders, pillows or any other shape or structure which allows a greater flow of fluids in the fracture. The SMA proppants are injected in combination with dissolvable proppant particles in a slurry of the SMA proppants and the dissolvable solids in a hydraulic fluid into the fracture through the well. Generally, the weight ratio of SMA proppant to dissolvable proppant is from about 0.1 to about 50. The SMA proppant particles may be flushed with a higher temperature fluid or exothermic reaction to activate the SMA proppant to expand while the fracture is propped open by the hydraulic fluid and maintained in the fracture for a suitable period of time for the SMA proppant to reach at least the expansion temperature of the SMA proppant. Thereafter fluids are produced from the fracture through the well with at least a major portion of the dissolvable proppant particulates being dissolved or otherwise decomposed.

The SMA proppants may be produced in any desired shape by the techniques described in the '496 Patent, previously incorporated by reference.

These SMA proppants, as noted above, may be of any suitable shape and are typically in a compressed state as injected. Upon reaching the expansion temperature of the SMA proppants they expand and maintain the fracture open. The SMA proppants can be size adapted for fracture/injection process. During the fracturing of the subterranean formation the temperature of the formation is reduced around the fracture being created since the fracturing stream injected into the fracture is cooler than the formation. The SMA proppants are thus injected at a temperature lower than the formation temperature and lower than the expansion temperature of the SMA proppants.

The SMA proppants and associated particulates of varying sizes from millimeters to nanometers and dissolvable proppant particles and other proppant particles may be injected with the fracturing fluid to form the fracture or they may be subsequently injected into the fracture as a whole or into portions of the fracture in the areas near and around the wellbore. In either event, these proppants serve the normal purpose of maintaining the fracture open and increasing productivity while screening and preventing to the extent customarily achieved by proppants the release of formation fines into the wellbore. The dissolvable proppant particulates are desirably formed of a material which retains its shape and size in the fracturing fluid long enough to permit the fracture to occur but is sufficiently soluble or degradable in oil, water or gas due to the temperature in the formation to disintegrate or dissolve the dissolvable proppant particles after production is resumed through the fracture. Desirably the dissolvable proppant particulate is oil or water soluble and is desirable to be substantially completely dissolved as fluids are produced through the fracture.

The production of certain materials for use either alone or as alloys is described in U.S. Pat. No. 3,316,965 issued May 2, 1967 to David J. Watanabe and assigned on its face to Union Oil Company of California, and is hereby incorporated in its entirety by reference.

The dissolvable proppant particulates may comprise homogenous mixtures or blends of hydrocarbons or polymers. These blends have variable softening and melting points depending upon the particular hydrocarbon and polymer components of the blends and the proportion of each present. Generally the hydrocarbon materials are solids which are substantially insoluble at ambient temperature in the hydrocarbon formation fluids or carrier fluids used to deliver these blends to the underground location where they serve as proppants. The particular blends can be selected depending on their melting point, softening point, solubility in the formation fluid, solubility in the carrier fluids, the ambient temperature and the downhole or formation temperature. The materials which can be used in the blending of such materials involve materials as varied as oils, waxes, greases, polycyclic hydrocarbons, such as naphthalene, anthracene, phenanthrene, asphalt, and other hydrocarbon materials having oil solubility at formation temperatures. Preferred hydrocarbon blends comprises waxes such as crystalline and micro crystalline petroleum waxes, as well as beeswax, carnauba wax, candellila wax, montan wax and the like. Also fats and hardened oils may be used. Highly hydrogenated oils, including both animal and vegetable oils may be used. Particularly preferred materials are paraffinic petroleum waxes comprising primarily straight chain hydrocarbons containing eighteen or more carbon atoms.

A wide variety of suitable water soluble materials comprise glycerin, wintergreen oil and oxyezoadine oil (animal, vegetable or mineral). Typically an adhesive, such as collagen, may be used. Such materials are described in some detail in the '460 Patent.

As discussed previously, the fluid containing the SMA proppants and the dissolvable proppant may be injected as a fracturing fluid to form the fracture initially or it may be injected after the fracture has been substantially completed or it may be injected after the fracture has been formed to treat the area near the wellbore.

Dissolvable proppant particulates may comprise polymers tailored to meet the required conditions discussed above and may include polymers such as amides, phenolic resins, polyethylenes and the like. The blends which are most useful are those which have a softening point starting at a melting point from about 130 to about 100° F. Such materials are further described in the '965 Patent.

The use of the SMA proppants and the dissolvable proppant particulates results in positioning the SMA proppants in the formation in an expanded configuration after injection in a compressed configuration. These materials function as proppants to hold the formation open and the dissolvable proppant particulates included in the fluid assist in forming the fracture but are readily dissolved to provide additional space between the SMA proppants for the flow of fluids from the fracture. Since there is no solid proppant to be recovered from the fracture and since the flow spaces in the fracture have been increased, the fracture is designed to produce fluids from the subterranean formation at an increased rate without the disadvantages of the flow back production of proppants into the well. The removal of the dissolvable proppants permits a gradually increased flow rate from the fracture and a reduced fines flow back from the fracture as a result of the gradually increased flow rate.

This invention is useful with cased or open hole fracturing methods and may also be used in horizontal, deviated or high-pressure, high-temperature fracturing jobs.

Typically the SMA proppants comprises from about 50 to about 56 atomic percent nickel in nickel-titanium alloys. Desirably the nickel-titanium alloys contain an atomic percent nickel required to produce shape memory alloys having a desired expansion temperature. Other shape memory alloys include copper-aluminum-zinc (CuAlZn), nickel-titanium-copper (NiTiCu), copper-aluminum-nickel (CuAlNi), Au—Cd, Ni—Mn—Ga, Co—Ni—Ga and other secondary or tertiary intermetallics that exhibit shape memory effects as previously mentioned herein. SMA proppants as previously noted have a tailored memory expansion temperature below the temperature at which the fluids are prepared and injected but above the temperature of the subterranean formation in which the fracture is placed. Typically the SMA proppants are contained in the fracturing fluid or other injection stream in amounts sufficient to achieve the fracturing objectives both during fracturing and subsequent to production.

Similarly the dissolvable proppants are used in amounts sufficient to achieve the fracturing objectives. The amounts of each will vary dependent upon the formation properties.

As discussed previously the fluid containing the SMA proppants and the dissolvable proppant may be injected as a fracturing fluid to form the fracture initially or it may be injected after the fracture has been substantially completed or it may be injected after the fracture has been formed to treat the area near the wellbore.

In any event, such water and oil soluble proppant materials are well known to those skilled in the art and any suitable material which meets the temperature and solubility requirements may be effectively used.

As previously indicated the dissolvable proppant is desirably designed to maintain its shape and size during fracturing or subsequent injection. While the size may be slightly reduced during injection, the proppant substantially maintains its size and shape during injection into the fracture. The proppant then is dissolved at the formation temperature. Desirably the proppant material is designed to have an increased solubility at the formation temperature. In other words, the proppant is relatively slowly dissolved, if at all, in the injection fluid or the formation fluid encountered in the formation of the fracture. As the proppant remains in the fracture and as the formation returns to its normal temperature after the fracture, the proppant becomes increasingly soluble and is desirably dissolved and recovered in or as a liquid.

According to the present invention, the positioning of proppants which transform to an expanded position after injection provides for adequate support to maintain the fracture in an open position. While the use of additional proppants may be effective in facilitating the formation of the fracture, dissolvable proppants will remain in the formation until the formation reaches an elevated formation temperature at which they begin to dissolve and at which the SMA proppants begin to expand. This optimizes the effectiveness of the fracture since the fracture is maintained in an open position by the SMA proppants which are in an expanded condition and therefore retained in position because of their expansion into engagement with the inside of the fracture, whereas the dissolvable proppants which have no such engagement may tend to backflow. They are retained in the fracture by the expanded SMA proppants as they tend to dissolve and are produced as a dissolved material.

The present invention has thus synergistically improved the effectiveness of formation fractures to produce high flow rates and to reduce the backflow of particulate material into the well.

While the present invention has been described by reference to certain of its preferred embodiments, it is pointed out that the embodiments described are illustrative rather than limiting in nature and that many variations and modifications are possible within the scope of the present invention. Many such variations and modifications may be considered obvious and desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments. 

1. A method of increasing productivity while reducing the production of particulate proppants during production of fluids from a hydraulic fracture in a subterranean formation penetrated from an earth surface by a well, the method comprising: a) injecting a fluid comprising smart memory alloy proppants having an expansion temperature below a temperature of the subterranean formation and dissolvable proppant particulates into the fracture through the well; b) maintaining the smart memory alloy proppants in the fracture for a time sufficient for the smart memory alloy proppants to reach at least the expansion temperature; and, c) producing fluids from the fracture through the well and dissolving at least a major portion of the dissolvable proppant particulates.
 2. The method of claim 1 wherein the fluid is injected from a cased or an open hole well to produce a fracture zone in the subterranean formation.
 3. The method of claim 1 wherein the smart memory alloy proppants comprise alloys of copper-aluminum-zinc (CuAlZn), nickel-titanium-copper (NiTiCu), copper-aluminum-nickel (CuAlNi) having a desired expansion temperature.
 4. The method of claim 1 wherein the smart memory alloy proppants comprise nickel-titanium alloys having an atomic percent nickel required to produce alloys having a desired expansion temperature.
 5. The method of claim 4 wherein the smart memory alloy proppants have an expansion temperature greater than a maximum handling and injection temperature but less than the temperature of the subterranean formation.
 6. The method of claim 1 wherein the fluid injected is a conventional fracturing fluid.
 7. The method of claim 1 wherein the fluid is injected after a conventional fracturing fluid.
 8. The method of claim 1 wherein the dissolvable proppant is oil soluble.
 9. The method of claim 1 wherein the dissolvable proppant is water soluble.
 10. The method of claim 1 wherein a weight ratio of smart memory alloy particles to dissolvable proppant is from about 0.1 to about
 50. 11. The method of claim 1 wherein the dissolvable proppant retains its size and shape during fracturing or subsequent injection.
 12. The method of claim 1 wherein the dissolvable proppants comprise hydrocarbon materials which are solids and substantially insoluble at ambient temperature in the subterranean formation fluids and carrier fluids used to inject the dissolvable proppants into the fracture where the dissolvable proppants are heated to a subterranean formation temperature at which the dissolvable proppants dissolve.
 13. The method of claim 1 wherein the dissolved proppants comprise particulate solid materials comprising mixtures or blends of hydrocarbons and polymers having variable softening points and melting points.
 14. The method of claim 1 wherein the dissolvable proppants comprise paraffinic petroleum waxes containing straight chain hydrocarbons containing at least eighteen carbon atoms.
 15. The method of claim 1 wherein the fluid is injected into a fracture subsequent to fracturing the subterranean formation to position the fluid in the near wellbore portion of the fracture.
 16. The method of claim 1 wherein an insoluble proppant is included in the injected fluid.
 17. The method of claim 16 wherein the insoluble proppant is an inorganic or an organic particulate material insoluble in the injected fluid and the produced fluids.
 18. The method of claim 16 wherein the insoluble proppant is sand or a ceramic particulate material. 